Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEM AND METHOD FOR OIL PRODUCTION EQUIPMENT
THAT MINIMIZES TOTAL EMISSIONS
COPYRIGHT STATEMENT
[0001] A portion of the disclosure of this patent document
contains material that is
subject to copyright protection. The copyright owner has no objection to the
facsimile
reproduction by anyone of the patent document or the patent disclosure as it
appears in the
Patent and Trademark Office patent file or records, but otherwise reserves all
copyright rights
whatsoever.
[0002] Trademarks used in the disclosure of the invention, and
the applicants, make no
claim to any trademarks referenced.
CROSS-REFERENCE TO RELATED APPLICATIONS
[0003] This application claims the benefit of United States
Provisional Patent
Applications No. 63147188, filed on February 08, 2021, and United States
Provisional Patent
Application No. 63148303, filed on February 11, 2021, U.S. Patent application
17/073,286
filed on October 16, 2020, all of which are incorporated by reference herein
in their entirety.
BACKGROUND OF THE INVENTION
1) Field of the Invention
[0004] The invention relates to the field of oil and gas
production and transportation and
methods to reduce the emissions of methane, other hydrocarbons, criteria
pollutants, and
non-criteria pollutants.
[0005] Natural gas is displacing coal in the power generation
sector due to reduced costs
and reduced Green House Gas (GHG) emissions. However, current methods of oil
and gas
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production and transportation result in significant emissions of methane,
other hydrocarbons,
criteria pollutants, and non-criteria pollutants. Methane is a highly potent
greenhouse gas, with
more than 80 times the climate warming impact of carbon dioxide over the first
20 years after
it is released. Other pollutants released from oil and gas production and
transportation also
result in climate warming impacts, affect regional air quality, produce
surface level ozone and
smog, negatively affect human health, and result in other environmental and
socioeconomical
impacts.
[0006] One way to quantify the magnitude of the methane leakage
is to divide the total
amount of methane produced each year from natural gas and oil infrastructure
by the total
amount of methane emitted each year by all sources
[0007] The Environmental Protection Agency (EPA) has estimated
this methane leak rate
to be 1.4 percent.
[0008] However, a recent study that reviewed results from more
than 130 other emissions
studies shows the U.S. oil and gas industry is leaking 13 million metric tons
of methane each
year. This means that the methane leak rate is 2.3 percent, indicating that
the former EPA study
significantly underestimated emissions.
[0009] An Environmental Defense Fund (EDF) study showed that a
methane leak rate of
greater than 3 percent would result in no immediate climate benefits from
retiring coal-fired
power plants in favor of natural gas power plants.
[0010] One maj or cause of emissions at production sites is
fugitive emissions. There are
several potential sources of fugitive emissions throughout the oil and natural
gas sector.
[0011] Fugitive emissions occur when connection points are not
fitted properly or when
seals and gaskets start to deteriorate. Changes in pressure or mechanical
stresses can also cause
components or equipment to leak. Potential sources of fugitive emissions
include but are not
limited to agitator seals, connectors, pump diaphragms, flanges, instruments,
meters, open-
ended lines, pressure relief devices, pump seals, valves, and improperly
controlled liquid
storage tanks.
[0012] Another source of methane emission from oil and gas
processing equipment is
pneumatic controllers. These controllers use the produced gas under pressure
for actuation and
are considered a major source of emissions. An EPA report indicated around
477,000
pneumatic controllers are in use at natural gas production sites in the United
States. These
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controllers are estimated to emit 334 Kg/yr. of methane (17.4 billion cubic
feet (bcf) of
methane), for an average of 4.2 scf/h of methane / device. They also release
other pollutants
which are present in the produced gas being used.
[0013] Other emission sources during production include but are
not limited to pneumatic
pumps and centrifugal and reciprocating compressors.
[0014] Gas powered pneumatic pumps are generally used at oil and
natural gas production
sites for methanol and chemical injection where electricity is not readily
available, and they
can be a significant source of emissions. Typically, these pumps include
plunger pumps with
a diaphragm or large piston on the gas end and a smaller piston on the liquid
end. This enables
a high discharge pressure with a varied but much lower pneumatic supply gas
pressure.
Pneumatic diaphragm pumps are used widely in the onshore oil and gas sector to
move larger
volumes of liquids per unit of time at lower discharge pressures than chemical
and methanol
injection pumps. The usage of these pumps is episodic, including transferring
bulk liquids such
as motor oil, pumping out sumps, and circulation of heat trace medium at well
sites in cold
climates during winter months.
[0015] In a reciprocating compressor, emissions occur when
natural gas leaks around the
piston rod when pressurized natural gas is in the cylinder. Over time, during
operation of the
compressor, the rod packing system becomes worn and will need to be replaced
to prevent
excessive leaking from the compression cylinder. Emissions are today
controlled by
replacement of the compressor rod packing, replacement of the piston rod, and
the refitting or
realignment of the piston rod. Emissions from centrifugal compressors depend
on the type of
seal used: either "wet", which use oil circulated at high pressure, or "dry",
which use a thin
gap of high-pressure gas. Dry seals are much more efficient, but both result
in the release of
emissions.
[0016] The configuration of surface wellhead fluids processing
equipment used by oil
producers varies from basin to basin and from producer to producer. However,
the current state
of the art implementation usually involves three to five steps of separation
which progressively
transition from higher to lower pressure until the cmde pressure finally
reaches atmospheric
pressure in the local storage tanks. The wellhead fluid is usually choked back
to between 80
and 450psi. The fluid enters a three-phase separator to separate the water,
crude and wet gas.
In some basins, the separator is heated to drive more of the gas out of the
crude. However, at
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80-450psi there is still a lot of gas entrenched in the crude and there are
liquids entrenched in
the gas. After that initial separation the wet gas, which still contains some
oil, is typically
injected into the midstream gathering line and the crude goes to a lower
pressure vessel to
enable more gas to escape the liquid. That gas is then typically compressed
and also injected
into the midstream gathering line. The crude may than go to a vertical vessel
called a vapor
recovery tower (VRT) at an even lower pressure so that more gas can be
separated from the
crude. That gas is typically then compressed and injected into the gathering
line. Last, the crude
is typically dumped into atmospheric storage tanks where the last remining
entrenched gases
escape the crude. Those gases are typically collected by a specialty
compressor called a Vapor
Recovery Unit or VRU and either flared or injected into the gathering line.
[0017] Crude stored in the on-site storage tanks is typically
either injected into a midstream
crude gathering line through a Lease Automatic Custody Transfer (LACT) unit or
is loaded
periodically into truck or rail transports. The loading of the crude is also a
source of emissions,
as -thief hatches" are opened in the top of the tank which allows the release
of evolved vapors
from the head space of the tank and from the agitation of the crude during
loading activities.
Also hydrocarbon vapors present in the transport and in the loading lines are
displaced by the
loaded crude, and these vapors are also typically released into the
environment or may be
routed to a combustor or flare.
[0018] Another source of well pad emissions is the flare. Gas is
typically disposed of onsite
in the U.S. either through combustion in an open tip flare (which is what is
shown in most of
the images of flaming oilfield flares in the media), or in a closed flare,
called a combustor
(which usually looks like a chimney or a barrel and does not typically have a
visible flame). In
ideal circumstances, the flare is used only for emergency situations where gas
is produced but
it cannot be evacuated. In that case, it is less hazardous and polluting to do
a controlled burn
of the gas rather than venting it. However, over the last decade, continuous
flaring has become
a routine part of unconventional oil production operations.
[0019] Modern flares combust between 95% to 99.8% of the gas and
0.2% to 5% of the
gas escapes combustion releasing methane, Volatile Organic Compounds (VOCs),
and other
pollutants directly into the environment. Incomplete combustion in the flare
also results in
criteria pollutant emissions including but not limited to VOCs, nitrogen
oxides primarily nitric
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oxide and nitrogen dioxide (N0x), Sulfur oxide (S0x), carbon monoxide and
particulate
matter.
[0020] When there is a need to perform maintenance on the oil
production equipment, for
safety reasons, any hydrocarbon inventory contained within that equipment is
typically
evacuated to a standby tank. That tank is usually outside the emission control
regime, resulting
in venting of the process gases resulting in emissions.
[0021] Additional sources of emissions are from upset conditions
such as the release of
pressure relief valves (which can occur during process upsets and other
occasional operational
events) and gas venting during maintenance of the gas processing equipment,
which can
include but is not limited to the purging of lines, knock out vessels and
storage tanks.
[0022] Perhaps the least understood source of emissions results
from the interdependency
among nearby well pads and between each pad and the midstream company.
Usually, there is
a gas evacuation pipeline that connects multiple pads to the midstream line.
The pipeline has
a capacity that is determined by its diameter and its operating pressure.
However, because of
the huge variability in production from unconventional oil well sites, there
is typically a
chronic shortage of evacuation capacity. The midstream does not want to invest
in a very large
pipeline that, after the connected shale wells go through their rapid decline
curve will be
oversized in as little as a year later. As a result, when a new pad is brought
online, it's very
high initial production of gas can overwhelm the gathering line capacity,
forcing many of the
other nearby pads that are connected to that line to shut in or to flare.
Since there is most often
no communication among pads, the sudden disappearance of evacuation capacity
surprises the
producers. This upset condition can result in massive flaring on the nearby
pads until the
producers react and can curtail their production to fit the available
capacity. The same
circumstance can occur in other situations including but not limited to when
the midstream
company needs to perform maintenance on the pipeline, when they remove
blockages or slugs
from the line, or when they shut the pipeline down due to maintenance at the
gas processing
facility.
[0023] A typical wellhead fluid will traverse between 5 and 10
"unit operations" on the
pad. Each one of these unit operations may have components that add to site
complexity and
can result in emissions, including but not limited to isolation valves,
actuators, knockout
vessels, retention vessels, overflow and blowdown connections, and storage.
Many of these
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unit operations may involve or have a connection to systems including but not
limited to
compressors, metering skids, combustors or flares and other ancillary
production or safety
equipment.
[0024] In total, the number of point sources of fugitive
emissions on a typical pad can
easily exceed 100 independent point sources. Although each of these fugitive
emission sources
may emit a very small amount of methane, other hydrocarbons, and pollutants,
the cumulative
environmental impact across all the wells and all the pads in each basin can
be massive.
[0025] The sheer number of point emission sources and the
diminutive nature of each of
the emissions makes the issue of fugitive emissions reduction from oil field
surface
infrastructure a very difficult problem to solve.
[0026] Accordingly, there is a need for a method to reduce the
emissions from oil and gas
production and transportation. A solution to at least one of the
aforementioned problems
with regard to current emissions from production and transportation of oil and
gas
underscores the need for a method to reduce the emissions of methane, other
hydrocarbons,
criteria pollutants, and non-clitetia pollutants.
BRIEF SUMMARY OF THE INVENTION
[0027] The instant invention in one form is directed to a method
and system for
eliminating emissions from crude production facilities through the
stabilization of crude oil at
pressure.
[0028] In a first implementation of the invention, the method
involves the reduction of
the total emissions from oil production facilities vs traditional processing
methods through
the removal of entrained volatile gases from the crude oil (stabilizing the
crude) and the
introduction into that stabilized crude of hydrocarbon liquid molecules which
would
otherwise be evacuated from the production site entrained within the produced
gas. By
performing this stabilization at pressure, a much simpler system can be
utilized versus
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traditional processing methods, which will reduce the need for combustion
sources on the
pad and significantly reduce fugitive and other emissions.
[0029] One system which can be used to achieve this method is a
comprehensive end-to-
end solution for surface well site crude and gas conditioning with minimized
emissions.
[0030] The system separates wellhead fluids into streams which
could include but are not
limited to water, stabilized crude, propane rich NGLs, and lean residue gas.
[0031] The system consists of, but is not limited to, an
integrated three-phase separator, a
reboiler, a stabilization column, an overhead condenser with a dynamic reflux
rate, and a
three-phase reflux drum.
[0032] The conditioned crude may or may not be subcooled after
exiting the system.
[0033] A feedback loop may or may not be used to prevent fluids
from entering the
system when the midstream evacuation line is unable to accept gas.
[0034] If the crude is not sufficiently stabilized before
leaving the system it may or may
not be recycled within the system for further conditioning.
[0035] The operating pressure of the system may or may not be
higher than the
midstream gas evacuation pressure. If it is higher, this may eliminate the
need for gas
compression on the pad. If it is lower, this may reduce the need for gas
compression on the
pad vs traditional processing systems.
[0036] The instant invention is furthermore a method and a
system for stabilizing crude
at higher than atmospheric pressure with the goal of reducing total emissions
from oil
production facilities comprising:
a. One or more separation systems to separate the hydrocarbon liquids,
hydrocarbon gases and water,
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b. One or more vertical separation systems utilizing a reboiler,
c. Optionally one or more reflux systems to further separate entrenched gases
from the liquid phase,
d. Optionally one or more systems that collect the overhead gases from the
first
and second systems and cool it to near ambient temperature,
e. Optionally one or more systems that separate the condensed liquids from the
third system into water, condensed hydrocarbons liquid and gaseous
hydrocarbons, and
f. An instrumentation and control system.
[0037] These and other objects, features, and advantages of the
present invention will
become more readily apparent from the attached drawings and the detailed
description of the
preferred embodiments, which follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0038] A further understanding of the nature and advantages of
particular embodiments
may be realized by reference to the remaining portions of the specification
and the drawings,
in which like reference numerals are used to refer to similar components. When
reference is
made to a reference numeral without specification to an existing sub-label, it
is intended to
refer to all such multiple similar components.
[0039] Fig. 1 shows a process flow diagram for the system, which
is one implementation
of the method.
[0040] Fig. 2 shows a traditional oil production facility.
[0041] Fig. 2A shows the tank farm area of Fig. 2
[0042] Fig. 2B shows the separator area of Fig. 2
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[0043] Fig. 2C shows the well head area of Fig. 2
[0044] Fig. 3 shows a schematic diagram of a traditional oil
production facility.
[0045] Fig. 4 shows a schematic diagram for a system which is
one implementation of
the method.
[0046] Corresponding reference characters indicate corresponding
parts throughout the
several views. The exemplifications set out herein illustrate embodiments of
the invention
and such exemplifications are not to be construed as limiting the scope of the
invention in
any manner.
DETAILED DESCRIPTION
[0047] While various aspects and features of certain embodiments
have been summarized
above, the following detailed description illustrates a few exemplary
embodiments in further
detail to enable one skilled in the art to practice such embodiments. The
described examples
are provided for illustrative purposes and are not intended to limit the scope
of the invention.
[0048] In the following description, for the purposes of
explanation, numerous specific
details are set forth in order to provide a thorough understanding of the
described
embodiments. It will be apparent to one skilled in the art however that other
embodiments of
the present invention may be practiced without some of these specific details.
Several
embodiments are described herein, and while various features are ascribed to
different
embodiments, it should be appreciated that the features described with respect
to one
embodiment may be incorporated with other embodiments as well. By the same
token
however, no single feature or features of any described embodiment should be
considered
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essential to every embodiment of the invention, as other embodiments of the
invention may
omit such features.
[0049] In this application the use of the singular includes the
plural unless specifically
stated otherwise and use of the terms "and" and "or" is equivalent to
"and/or," also referred to
as "non-exclusive or" unless otherwise indicated Moreover, the use of the term
"including,"
as well as other forms, such as "includes" and "included," should be
considered non-
exclusive. Also, terms such as "element" or "component" encompass both
elements and
components including one unit and elements and components that include more
than one
unit, unless specifically stated otherwise.
[0050] Lastly, the terms "or" and "and/or" as used herein are to
be interpreted as
inclusive or meaning any one or any combination. Therefore, "A, B or C" or "A,
B and/or C"
mean "any of the following: A; B; C; A and B; A and C; B and C; A, B and C."
An exception
to this definition will occur only when a combination of elements, functions,
steps or acts are
in some way inherently mutually exclusive
[0051] As this invention is susceptible to embodiments of many
different forms, it is
intended that the present disclosure be considered as an example of the
principles of the
invention and not intended to limit the invention to the specific embodiments
shown and
described.
[0052] The term stabilized crude or conditioned crude refers to
crude that meets certain
conditions such as a predefined Reed Vapor Pressure (RVP).
[0053] A stripping column is a tower similar to a stabilization
column, but does not use
an overhead condenser, reflux drum or reflux fluid.
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[0054] Overhead condenser is a type of heat exchanger that
accepts gas from the top half
of the fractionation column and chills it down causing entrenched water and
heavier
hydrocarbons to condense.
[0055] The terms emissions, or total emissions, when used
herein, includes methane
emissions, other hydrocarbon emissions, criteria pollutant emissions, non-
criteria pollutant
emissions, greenhouse gas emissions, and all other molecules emitted to the
atmosphere from
oil production facilities. When used herein, emissions refer to these
different types of
emissions, both collectively and individually.
[0056] Production fluid or wellhead fluid is the fluid mixture
of oil, gas and water that
flows to the surface of an oil well from a reservoir.
[0057] A three-phase separator is an oblong vessel with a weir
inside. The vessel receives
production fluid. The water is accumulated on one side of the weir. Liquid
hydrocarbons
float over the water and spill over the weir. Gaseous hydrocarbons leave the
solution and exit
at the top of the vessel.
[0058] A distillation column is a tower with media inside. Heat
is provided at the bottom
of the column and heats the liquid hydrocarbons. As they heat, the lighter
hydrocarbon chains
evaporate and flow to the top of the column. Heavier hydrocarbon chains flow
to the bottom
of the column. This process results in fractionation, or separation or
conditioning of the
hydrocarbon streams. The terms stabilization column, distillation column and
fractionation
column are used herein interchangeably.
[0059] Prior to a discussion of the preferred embodiment of the
invention, it should be
understood that the features and advantages of the invention are illustrated
in terms of a
system of the instant invention that separates wellhead fluids at pressure,
into water,
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stabilized crude, propane rich NGLs, and lean residue gas, by integrating a
three-phase
separator with a stabilization column, an overhead condenser with a dynamic
reflux rate, and
a three-phase reflux drum to minimize emissions of various gases. Therefore
one should
realize that many different embodiments are possible.
[0060] The method of the instant invention works at a pressure
of 100psi to 600psi
[0061] The NGLs are produced at a pressure of 0psi to 600psi.
[0062] In one embodiment, the crude is flashed to atmospheric
tanks.
[0063] The vapor pressure of a liquid NGLs stream from the
process may range from 2
psi to 350 psi.
[0064] The temperature of the liquid NGLs from the present
process may range from -40
C to 300 C.
[0065] In one embodiment, the gas from the three-phase separator
is injected at the top of
the fractionation column where it, together with the reflux gas from the top
of the column,
are refrigerated by an overhead condenser. The condensed water is rejected
from the
hydrocarbon liquids in a second specialized three-phase separator, called the
reflux drum
The gas leaves the reflux drum at pressure and contains mostly methane,
ethane, and some
propane. The hydrocarbon liquids from the reflux drum can either be recycled
back into the
column or can leave the system as a propane rich NGL stream.
[0066] In another embodiment, the decision of the amount of the
liquids that should be
reinjected into the column, called the reflux ratio, is dynamically controlled
by the control
system based on the desired specification of the product.
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[0067] In another embodiment, the liquid hydrocarbon stream from
the three-phase
separator is heated for proper stabilization at high pressure at the
fractionation column,
resulting in a hot crude stream containing only a small amount of volatile
components.
[0068] In another embodiment, to finalize the stabilization, the
crude is directed from the
column to an ambient cooler The cooler sub cools the crude prior to directing
it to the tank
batteries, ensuring that no further gas separation will happen in the tank.
[0069] In another embodiment, a dynamic sampling system controls
the crude's
disposition. If the crude meets a specified vapor pressure, it is directed to
the atmospheric
storage tanks or to the product sales line either through or not through a
LACT unit. If it is
still too volatile, the system closes the inlet control valve, and the crude
is recycled back to
the three-phase separator.
[0070] In another embodiment, the system automatically adjusts
the temperature of the
reboiler to maximize the volume of the crude produced by maximizing the vapor
pressure of
the crude, while keeping it within the specified vapor pressure.
[0071] In another embodiment, the crude is injected directly to
the crude gathering line
through a LACT unit without going through local crude storage.
[0072] In another embodiment, the crude is injected directly
into the crude gathering line
directly from the system without going through a LACT unit.
[0073] In another embodiment, the dynamic controls offer
flexibility to create the spec
product Y-grade NGLs or L-grade NGLs.
[0074] In another embodiment, the dynamic controls offer
flexibility to create non-spec
NGLs.
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[0075] In another embodiment the NGLs are used as an enhanced
oil recovery (EOR)
stimulant.
[0076] In another embodiment, the NGLs are used as gas lift
fluid.
[0077] In another embodiment, the NGLs are blended with the gas
and sold to the gas
midstream through a gathering line, or are trucked to market, or are used
locally as fuel for
power generation or other uses, or are flared.
[0078] In another embodiment of the invention, a means is
provided to replace standard
wellhead fluid processing equipment necessary during oil and gas production
with a
specialized integrated system optimized for processing and separating wellhead
fluids into
separate wastewater, oil, NGLs and natural gas streams as needed.
[0079] In another embodiment of the invention, the fractionation
column has trays.
[0080] In another embodiment of the invention, the fractionation
column has random
packed media.
[0081] In another embodiment of the invention, in addition to
the NGLs and residue gas,
the fractionation column fractionates the crude further into refined products
such as light
naphtha, heavy naphtha, kerosene, diesel, vacuum gas oil and vacuum residue
oil, or any
combinations of this list, or into other refined products or product mixes.
[0082] In another embodiment, the fractionation column is
divided into two or more
columns to reduce the total height of the column, or to enable production of
purity products,
or for other purposes.
[0083] In another embodiment of the invention, the wellhead
fluid is not subcooled
before entering the system.
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[0084] In another embodiment of the invention, the stabilized
crude is not subcooled
after leaving the system.
[0085] In another embodiment of the invention, the overhead
condenser uses a cooling
system which could consist of, but is not limited to, an ambient air chiller
or a mechanical
refrigeration system
[0086] In another embodiment of the invention, a stripping
column is used rather than a
fractionation column, eliminating the need for the overhead condenser and
reflux drum.
[0087] In another embodiment of the invention, the horizontal
and vertical vessels are all
mounted on a single skid or on multiple skids.
[0088] In another embodiment of the invention, the control
system is connected to a
central system and/or operations center through means including, but not
limited to, a cellular
communication link, or a satellite communication link, or a local area
network.
[0089] In another embodiment of the invention, the central
control system enables remote
operators to monitor, control and manage several sites from one location.
[0090] In another embodiment of the invention, operators can
prioritize the volume of
production of each site.
[0091] In yet another embodiment of the invention, production
from sites that are
connected to the same gas evacuation pipeline can be dynamically prioritized
to maximize
the utility of the available evacuation capacity.
[0092] Referring to the Figures an example embodiment of the
process is described
below.
[0093] Figure 1, 2, 2A, 2B, 2C, 3 and 4 provides the tag names
referred to herein.
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[0094] In one embodiment, the present invention relates to
processing of wellhead fluid
in an integrated system to increase crude volume while reducing emissions,
including those
from combustion sources.
[0095] The present invention stabilizes crude oil in a "single-
step, high-pressure"
application, providing conditioned, sub-cooled crude oil to the tank
batteries/on-site storage.
The conditioned, sub-cooled crude oil does not off-gas within tank
batteries/on-site storage
or low-pressure vessels, eliminating emissions from tank batteries/on-site
storage due to off-
gassing. The "single-step, high-pressure" conditioning consolidates most
emissions into a
single, high-pressure gas stream.
[0096] NGLs and natural gasolines are separated in a "single-
step, high-pressure"
process. NGLs are optionally removed in the "single-step, high-pressure"
process as high-
pressure liquid stimulant for reinjection downhole in an EOR process,
improving well
production. Natural gasolines are treated in the "single-step, high-pressure"
process and
combined with stabilized crude oil.
[0097] "Single-step, high-pressure" treatment of crude oil
increases overall crude oil
production by selectively recovering butane and longer hydrocarbon chain
components and
combining them with the remaining crude.
[0098] In one preferred embodiment, the invention provides a
"single-step, high-
pressure" processing system shown in the drawings and a method for separation
of crude oil,
natural gas liquids, water, and associated gas by treatment of wellhead fluid
in the following
steps:
[0099] Wellhead fluid [100] containing a mixture of hydrocarbons
and water flow
through a pressure regulating valve [101] to stabilize system inlet flow.
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1001001 The pressure stabilized stream [102] enters the inlet
three-phase separator [103]
which is equipped with coalescing technologies to reduce the settling time of
the
water/hydrocarbon emulsion. The discrete hydrocarbon stream spills over the
weir and exits
the separator.
1001011 Bulk water [135] is removed from the separator and is regulated
through a control
valve [136] for disposal [140].
1001021 The liquid hydrocarbon stream [104] exiting the inlet
three-phase separator [103]
is regulated by a control valve [105] into a distillation column [107] which
contains trays, or
is a packed bed, or is of some other technology. Within the column, the
hydrocarbon mixture
is separated by component boiling point.
1001031 The gaseous hydrocarbons [117] exiting the inlet three-
phase separator [103] are
regulated through a control valve [118]. The gaseous hydrocarbons [119] may
mix with the
distillation column vapor [108] for further processing in the air-cooled
condenser [110].
Alternatively, the gaseous hydrocarbons [119] may mix with the overhead phase
separator
gas [115] and exit the system [116] without further processing. The flow path
is selected by
two diverting valves [121 and 123].
1001041 The light hydrocarbons [108] exit the top of the column as a vapor.
The light
hydrocarbons [109] enter an air-cooled condenser [110] to generate a partially
condensed
stream of hydrocarbons [111] near ambient temperature, which are then
separated in an
overhead phase separator [112].
1001051 The overhead phase separator vapor [113] that is leaving the overhead
phase
separator [112] is metered through a control valve [114] as conditioned gas
[115].
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1001061 Bulk water [138] is removed from the overhead phase separator [112],
metered
through a control valve [139], and mixed with upstream bulk water [137] for
disposal [140].
1001071 Hydrocarbons [125] exit the overhead phase separator [112] and are fed
to a
reflux pump [126]. The pump discharge [127] is metered by a valve [128] to
maintain a
steady reflux flow [129] to maintain product specification Excess hydrocarbon
liquid [130]
is optionally fed to an injection pump [131] The liquid [132] is metered by a
valve [133] to
maintain a steady flow [134] and may be used in one of several ways, including
but not
limited to, increasing oil production in an EOR process.
1001081 Hydrocarbon liquid [141] leaving the bottom of the distillation column
[107]
feeds a reboiler [142] to partially vaporize the liquid stream. The reboiler
may be fired or
electric or some other technology. Reboiler operating temperature is
determined based on
desired crude oil specifications, between 150 C and 400 C.
1001091 Reboiler vapor [143] exiting the reboiler [142] is
returned to the distillation
column [107] near the bottom of the column.
1001101 Reboiler liquids [144] exiting the reboiler [142] are metered through
a control
valve [146] and are cooled to near-ambient temperature with an air-cooled heat
exchanger
[148].
1001111 A slipstream from the cooled crude [149] is continuously analyzed with
a vapor
pressure analyzer to verify product quality.
1001121 If the cooled crude [149] meets the vapor pressure requirement, the
crude product
[150] flows through the product shutoff valve [151] and out of the system
[152] to be stored
on-site or injected directly into the crude gathering line.
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[00113] If the cooled crude []49] does not meet the vapor pressure
requirement, the off-
spec crude [153] is pumped [154] through the off-spec recirculation valve
[156] to be
reprocessed in the feed separator [103].
[00114] An example wellhead fluid stream is separated according to the
described process.
Compositions, temperatures, pressures, and other relevant data are given below
for major
process streams. Major product streams include NGLs prior to pumping for well
stimulation,
residue gas for further processing or sale, conditioned crude, and wastewater
for disposal.
This example demonstrates elimination of crude off-gassing in storage tanks,
substantial
recovery (98.7%) of C5+ components in crude product, and optional production
of NGLs
suitable for downhole injection in an EOR process or transportation.
[00115] Typical results are shown in Table 1 and Table 2,
Wellhead Separator
Separator
Quantity UOM Fluid Separator Hydrocarbons Water
Residue
Gas (117)
Gas (116)
(100) (104)
(135)
Vapor Fraction: 0.5057 1 0 0
1
Temperature: `C 65.56 65.56 65.56
65.56 38
Pressure: bara 25 25 25 25
18
Molar Flow: kgmol/h 823.9 416.7 388.8
18.42 486.3
Molecular Weight: kg/kgmol 59.8 31.34 92.27
18.02 32.53
Mass Flow: kg/h 49270 13060
35880 331.8 15820
Act. Volume Flow: m3/h 459.2 401.1 57.74
0.3396 594.4
Mass Density: kg/m3 . 107.3 32.56 621.4
976.9 26.62
mol
Composition fraction
CO2 0.3% 0.6% 0.1% 0.0%
0.5%
Nitrogen 0.2% 0.4% 0.0% 0.0%
0.3%
H20 2.9% 1.1% 0.3%
100.0% 0.4%
Methane 27.4% 48.8% 5.8% 0.0%
44.8%
Ethane 5.7% 8.2% 3.2% 0.0%
8.4%
Propane 24.1% 25.2% 24.0%
0.0% 29.0%
i-Butane 6.7% 4.8% 9.0% 0.0%
5.9%
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n-Butane ................................... : 16.0% .................. 10.0%
23.3% :0.0% 10.7%
i-Pentane 0.5% 0.2% 0.9% 0.0%
0.0%
n-Pentane 0.8% 0.2% 1.3% 0.0%
0.0%
:
n-Hexane 0.9% 0.1% 1.7% 0.0%
0.0%
C7+ 14.5% 0.3% 30.5% 0.0%
0.0%
Table 1
ll
Condenser We Crude Conditioned
Quantity UOM
Water (138) Stimulant
(144) Crude
(152)
(127)
Vapor Fraction: 0 0 0 0
Temperature: `C 38 38 259 49
Pressure: bara 18 18 20 1
Molar Flow: kgmol/h 3.589 155.5 160 160
Molecular Weight: kg/kgmol 18.02 49.87 158.1 158.1
Mass Flow: kg/h 64.66 7754 25290 25290
Act. Volume Flow: m3/h 0.06479 15.27 .. 49.03 35.27
Mass Density: kg/m3 998 507.7 515.8 717.2
mol
Composition fraction
CO2 0.0% 0.1% 0.0% 0.0%
Nitrogen : 0.0% 0.0% 0.0% 0.0%
H20 100.0% 0.1% 0.0% 0.0%
Methane 0.0% 5.1% 0.0% 0.0%
Ethane 0.0% 3.8% 0.0% 0.0%
Propane 0.0% 36.9% 0.1% 0.1%
i-Butane 0.0% 15.7% 1.4% 1.4%
n-Butane .................................. 0.0% 37.4% 13.7% 13.7%
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1-Pentane 0.0% 0.2% 2.3% 2.3%
n-Pentane 0.0% 0.3% 3.6% 3.6%
n-Hexane 0.0% 0.1% 4.4% 4.4%
C7+ 0.0% 0.2% 74.6% 74.6%
Table 2
1001161 As shown in Fig.4, in one embodiment, the invention provides a
processing
system shown in the drawings and a method for stabilizing crude oil at
pressure by treatment
of wellhead fluid in the following steps:
1001171 The wellhead fluids [401] may pass through zero, one or more pump(s)
or
compression device(s) [440] to increase its pressure to the operating
pressure. Then the
wellhead fluids may pass through zero, one or more flow control valves [443].
The flow
control valve(s) [443] may be actuated by a control system or set manually or
preset. The
flow control valve(s) [443] may restrict flow into the system when one or more
pressure
sensors [444] indicated that there are gas evacuation constraints. The
wellhead fluids are sent
to zero, one or more phase separators [402, 406] These phase separators may be
referred to
as, but not limited to, allocation separator, HLPC separator, high pressure
separator, test
separator, heater treater, vertical separator, or bulk separator. The
separator(s) [402, 406]
may collect wellhead fluid from one or more wellheads [401]. The separator(s)
[402, 406]
may be two-phase separators or three-phase separators. The wellhead fluids may
be chilled or
heated by zero, one or more heaters or chillers or heat exchangers [441]. The
heater(s),
chiller(s) or heat exchanger(s) may be installed before phase separator(s)
[402] or before bulk
separator(s) [406] or after bulk separator(s) [406]. The separator(s) may
produce three
product streams: produced water stream(s) [403, 409], gaseous hydrocarbon
stream(s) [405,
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407], and liquid hydrocarbon stream(s) [434]. The water stream(s) [403, 409]
may contain
some amount of hydrocarbons. The gaseous hydrocarbon stream(s) [405, 407] may
contain
some amounts of liquid hydrocarbons and some water. The liquid hydrocarbon
stream(s)
may contain some amount of gaseous hydrocarbons and some water. The gaseous
hydrocarbon stream(s) produced by the separator(s) [405, 407] may go directly
to one or
more gas sales, evacuation or use lines [419], or it may be routed to one or
more column(s)
[410]. The gaseous hydrocarbon stream(s) may be routed to the top half of the
column(s)
[410] or to one or more overhead condenser(s) [427]. The name "overhead
condenser" does
not necessary indicate that the condenser is physically overhead. It merely
denotes that the
hydrocarbon stream originates at the top half of the column. The overhead
condenser(s)
[413] chill the hydrocarbon stream and route it to zero, one or more reflux
drum(s) [414].
The reflux drum(s) separate the hydrocarbon stream to two or more streams. A
gaseous
hydrocarbon stream [430]. A water rich stream [415]. A liquid hydrocarbon
stream [431].
The gaseous hydrocarbon stream [430] may contain some liquid hydrocarbons and
some
water. The water stream [415] may contain some liquid hydrocarbons and some
gaseous
hydrocarbons. The liquid hydrocarbon stream [431] may contain some gaseous
hydrocarbons
and some water. The gaseous hydrocarbon stream [430] may be routed to gas
line(s) [419].
The liquid hydrocarbon stream [431] may be further divided [432] such that
some of it will
be routed to the top half of the column to be used as reflux fluid [416] and
some of it will be
routed out of the system [433]. The ratio between the amount of reflux fluid
[416] and the
amount that is routed out of the system [433], known as the reflux ratio, may
be controlled by
zero, one or more control valve(s) [432]. The reflux ratio may range between
0% (all the
liquid hydrocarbon stream is routed out of the system) to 100% (all the liquid
hydrocarbon
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stream will be injected back into the column as reflux fluid). The reflux
ratio may be
determined dynamically by a control system or manually or be preconfigured.
The liquid
hydrocarbon steam that is routed out of the system [433] may be blended with
the gaseous
hydrocarbon stream and routed to gas line(s) [419] or produced as an NGL
stream [418].
1001181 The liquid hydrocarbon stream [434] enters the column through one or
more
injection point(s) [435]. The injection location of the liquid hydrocarbon
stream [434] may be
determined dynamically by a control system or manually or be preconfigured.
The
hydrocarbons at the bottom of the column are heated by a reboiler [426]. The
reboiler can be
controlled by a control system or set manually. The liquid hydrocarbon stream
produced by
the column [410] may be routed to zero, one or more sensor system(s) [436].
The sensor
system(s) may check if the liquid hydrocarbon stream would meet the crude
evacuation spec.
If the sensor system(s) deteimines that the liquid hydrocarbon stream would
not meet crude
evacuation spec, the liquid hydrocarbon stream may be routed back to the
beginning of the
process [437]. The routing of the off-spec liquid hydrocarbon stream may be
controlled by a
control system or manually or be preconfigured. The off-spec liquid
hydrocarbon stream may
be routed to the bulk separator [406] or to the phase separator [402] or to
the column [410].
The routing of the off-spec liquid hydrocarbon stream may be determined
dynamically by a
control system or manually or be preconfigured.
1001191 The on-spec liquid hydrocarbon stream [438] may be cooled by zero,
one, or
more condenser(s) [425]. Cooling the liquid hydrocarbon stream "locks" the
volatile
hydrocarbons in the liquid phase producing stabilized crude that meets the
crude evacuation
specs. In one embodiment, the condenser [425] is implemented as a heat
exchanger
exchanging heat with the incoming stream [442]. This is known as an
economizing heat
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exchanger. The on-spec crude can be routed to evacuation [421] or to one or
more onsite
crude tank(s) [420], Even if routed to crude tank(s), the stabilized crude
emissions would be
minimal.
1001201 The water streams [403, 409, 412, 415] are routed to zero, one, or
more water
tank(s) [422] If the water stream is routed to water tank(s) [422], the
emissions from the
water [439] could be routed to one or more emission control device(s) [423].
The water can
then be sent to disposal [424].
1001211 In one embodiment of the method, the system is collocated with one or
more
wellhead(s) on the same pad. In another embodiment, the wellhead(s) are
located in a remote
location and the wellhead fluid is piped into the system. In that embodiment,
wellhead fluid
from multiple locations may be routed into one system. In yet another
embodiment, the
wellhead(s) and the phase separator(s) are located in a remote location and
one or more of the
phase-separated streams are piped into the system. In that embodiment, phase-
separated
streams may be routed from multiple locations into the system.
1001221 Furtheiniore while referring now to the drawings Fig. 1 -4, and more
particularly
to Fig. 1, there is shown a system separates wellhead fluids, at pressure,
into water, stabilized
crude, propane rich NGLs, and lean residue gas by integrating a three-phase
separator with a
stabilization column, an overhead condenser with a dynamic reflux rate, and a
three-phase
reflux drum.
1001231 Fig. 1 shows a process schematic of an integrated system for well
fluids
processing.
1001241 In one embodiment, the process separation occurs by first adjusting
the pressure
of the fluids being produced from the well through a choke [100], then the
fluids go through
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a flow control valve that governs the amount of intake fluid to the system
[101]. Then the
fluid [102] is injected into a specialized three-phase separator [103]. The
three-phase
separator separates the stream into three streams: wastewater [135], liquid
hydrocarbons
[104], and gaseous hydrocarbons [117].
1001251 In one embodiment, the three-phase separator [103] includes a
coalescer to speed
up phase separation of water and hydrocarbons.
1001261 In one embodiment, the gaseous hydrocarbons [117] exiting the inlet
three-phase
separator [103] are regulated through a control valve [118]. The gaseous
hydrocarbons [119]
may mix with the distillation column vapor [108] for further processing in the
air-cooled
condenser [110]. Alternatively, the gaseous hydrocarbons [119] may mix with
the overhead
phase separator gas [115] and exit the system [116] without further
processing. The flow path
is selected by two diverting valves [121] and [123].
1001271 In one embodiment, the diverting valves [121] and [123] are
continuously
adjusted by the control system to ensure optimal product output.
1001281 In one embodiment, the light hydrocarbons [108] exit the top of the
column as a
vapor. This vapor [109] enters an air-cooled condenser [110] to generate a
partially
condensed stream of hydrocarbons [111] near ambient temperature, which are
then separated
in a three-phase reflux drum [112].
1001291 In one embodiment, vapor leaving the reflux drum [113] is metered
through a
control valve [114] as conditioned residue gas [115].
1001301 In one embodiment, the residue gas is injected into a midstream
gathering line
[116].
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1001311 In one embodiment, the water from the reflux drum [138] is removed
through a
control valve [139] and mixed with water from the main three-phase separator
[137] for
disposal [140].
1001321 In one embodiment, liquid hydrocarbon from the reflux drum [125] is
fed to a
reflux pump [126] The pump discharge [127] is governed by a valve [128] to
maintain a
steady reflux flow [129] to maintain product specification.
1001331 In one embodiment, excess hydrocarbon liquid [130] comprising mostly
of
ethane, propane, and butane (NGL) is fed to an injection pump [131] through a
control valve
[133] for reinjection to the wellhead [134] as miscible EOR fluid.
1001341 In one embodiment, the NGL stream [134] leaving the control valve
[133] is
pumped down hole to be used for the gas lift, where such gas lift may be
achieved through
use of one or more means including but not limited to use of a jet pump.
1001351 In another embodiment, that NGL fluid is stored in pressurized storage
tanks on-
site prior to transport to market.
1001361 In yet another embodiment, that NGL [134] is merged with the residue
gas [116]
and injected into the midstream gathering line.
1001371 In one embodiment, the liquid hydrocarbon [104] from the main three-
phase
separator [103] is injected [106] into a reflux column [107]. A reboiler at
the bottom of the
column [142], heats the liquid leaving the bottom of the column [141] to
partially vaporize
the liquid stream.
1001381 In one embodiment, the reboiler may be one of several types, including
but not
limited to a fired burner and an electric reboiler.
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1001391 In one embodiment, the reboiler operating temperature is determined
based on
desired crude oil specifications, and would normally range between 100 C and
500 C.
1001401 In one embodiment, vapor exiting the reboiler [143] is returned to the
bottom of
the distillation column [107].
1001411 In one embodiment, hydrocarbon liquids (stabilized crude), exiting the
reboiler
[144] are metered through a control valve [146] and are cooled to near-ambient
temperature
through means including, but not limited to, an air-cooled heat exchanger
[148].
1001421 In one embodiment, a slipstream from the sub-cooled stabilized crude
[149] is
continuously analyzed with a vapor pressure analyzer to verify product
quality. If the cooled
crude [149] does not meet the vapor pressure requirement, the off-spec crude
[153] is
pumped [154] through the off-spec recycling valve [156] to be reprocessed in
the feed
separator [103].
1001431 In one embodiment, if this crude [149] meets the vapor pressure
requirement, the
crude product [150] flows through the product shutoff valve [151] and out of
the system
[152] to on-site crude tanks or is injected into a crude gathering line
through a LACT unit.
1001441 In one embodiment, the system automatically adjusts the temperature of
the
reboiler to maximize the volume of the crude produced by maximizing the vapor
pressure of
the crude, while ensuring it remains within the specified vapor pressure.
1001451 In another embodiment, the crude is injected directly to the crude
gathering line
through a LACT unit without going through local crude storage.
1001461 In yet another embodiment, the crude is injected directly into the
crude gathering
line directly from the system without going through a LACT unit.
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1001471 In another embodiment, the system comprises of a stripping column
[107] rather
than a distillation column, eliminating the need for the overhead condenser
[110] and the
reflux drum [112]. That embodiment will not be capable of generating a
separate propane
rich NGL stream.
1001481 In the preferred embodiment, the system will replace nearly all the
equipment
currently used on an oil pad. Particularly the system will replace equipment
including but not
limited to the heater treaters, mid-pressure separation vessels, mid pressure
gas compressors,
vapor recovery tower, vapor recovery unit (VRU compressor), gas sale
compressors,
knockouts, oxygen scrubbers and high-capacity flares. In the preferred
embodiment, once the
new system is installed on a pad, there will be no need for most combustion
sources and
routine venting and flaring. It will also eliminate most fugitive emissions.
The emissions
reduction will be affected through implementation of different equipment than
that which is
traditionally used, thereby eliminating and reducing actual emissions sources
vs the
traditional approach, rather than through implementation of systems to control
existing
emissions sources by flaring.
1001491 Referring to Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C which shows a pad
with current
state-of-the-art emissions mitigation. From one or more well heads (Well Head
Area) the
well head fluid is transported via one or more underground pipes to one or
more high-low
heated pressure separators [Z-1010 to Z-1190]. The high-pressure side of the
separator
typically operates at 100psi to 1,000psi. The low-pressure side of the
separator typically
operates at a pressure of 80psi to 180psi. In each one of these separators
there is a burner
that heats the crude. The burner is typically burning field gas. The gas from
the high-pressure
side of the high-low heated pressure separator goes directly to one or more
gas sales lines
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typically through one or more meters (sales meter). The gas from the low-
pressure side of the
high-low heated pressure separator(s) [Z-1010-Z-1190], goes to one or more
compressor(s)
[Z-2030], to be injected into one or more gas sales lines typically through
one or more meters
(sales meter). The crude optionally goes to one or more bulk crude
separator(s) [Z-5400]
where the pressure is dropped further typically to under 80psi The gas
released by the bulk
separator(s) goes to one or more compressor(s) [Z-2020]. From that
compressor(s) [Z-2020]
the gas is injected into one or more gas sales lines typically through one or
more meters
(sales meter). The crude from the bulk separator(s) optionally goes to one or
more crude
scrubber(s) [Z-5100] where the pressure is further dropped typically below
20psi. The gas
from the crude scraper(s) [Z-5100] goes to one or more compressor(s) [Z-2010]
and from
there to one or more gas sales lines typically through one or more meters
(sales meter). The
crude from the crude scraper(s) [Z-5100] optionally goes to one or more vapor
recovery
tower(s) [V-5300] where the pressure is dropped typically below 1 Opsi. The
gas from the
vapor recovery tower(s) [V-5300] goes to one or more compressor(s) [Z-2000]
and from
there to one or more gas sales lines typically through one or more meters
(sales meter). The
crude from the vapor recovery tower(s) [V-5300] goes to one or more
atmospheric tank(s)
[TK-6100 ¨ TK-6450]. The vapors from the tank(s) go to one or more flares [FM-
9100 ¨
FM-9600] where they are combusted. The tank(s) vapors may optionally go to an
oxygen
scrubber [V-5500 ¨ V-5501], and from there to one or more compressor(s) [Z-
2000], and
from there to one or more gas sales lines typically through one or more meters
(sales meter).
Released produced water from each one of these steps is collected at each step
and routed to
atmospheric tanks [TK-6000 ¨ TK-6050]. The vapors from the water tanks go to
the flares
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[FM-9100 ¨ FM-9600]. From the tanks [TK-6100 - TK-6450] the crude is sent to
the LACT
skid [Z-8000] for evacuation.
1001501 Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C which shows the following
combustion
sources on the pad: One or more heated phase separators [Z-1010 to Z1190]. One
or more
compressors [Z-2000 to Z-2030]. One or more flares [FM-9100 ¨ FM-9600]. One or
more
generators [Z-2100]. In this embodiment there are 30 combustion sources on the
pad. In
addition, the pad depicted in Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C contains
almost 1,000 point
sources of fugitive emissions.
1001511 In Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C, when maintenance is performed
on any of
the pressurized vessels, pipes or other equipment, the gas in that equipment
is vented to the
atmosphere. The pressurized liquids are directed to the tanks [TK-6100 ¨ TK-
6450] or to one
or more standalone tank(s) [TK-6990] where the pressure is released, and the
gas is vented to
the atmosphere.
1001521 Referring to Fig. 3 describes the current state of the
art of crude stabilization at oil
production facilities. The wellhead fluids [301] are sent to one or more phase
separator(s)
[302]. The phase separator(s) produce two or three product streams. If it is a
three-phase
separator, it produces a water stream [312], a liquid hydrocarbon stream
[304], and a gaseous
hydrocarbon stream [303]. The produced water stream [312] contains some
hydrocarbons.
The liquid hydrocarbon stream [304] contains some water. The gaseous
hydrocarbon stream
[303] contains some water. If it is a two-phase separator or a tank, it will
produce a liquid
stream [304] and a gaseous hydrocarbon stream [303]. Both these streams [304,
303] will
contain some water. If the liquid hydrocarbon stream meets crude spec the
crude can be sold
[3 1 1]. If the liquid hydrocarbon stream does not meet crude spec, then the
pressure is
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reduced [309] and the liquid is injected into one or more additional phase
separator steps at a
lower pressure. This process repeats until the liquid hydrocarbon stream meets
crude spec
and is ready for sale. In each of the steps described above, some gaseous
hydrocarbon stream
[303] is released from the liquid phase. If the gaseous hydrocarbon stream is
released at a
pressure above the midstream evacuation pressure, then the gas is routed to
gas sales [310]. If
the gaseous stream is released at lower pressure, then if there is enough
volume of gas that
justifies the cost of running a compressor, or the volume is higher than what
regulations
allow to flare, the gas is compressed into the pipeline pressure [307] and is
sold [310]. If the
gaseous stream volume is insufficient to justify the cost of running a
compressor or the
volume is not high enough to generate emissions in excess of regulatory
requirements, the
gas is routed to one or more flares [308]. Similarly, if the gaseous stream
contains
contamination such as oxygen, it is also routed to flare(s) [305].
1001531 In a typical oil production site like that of Fig. 3,
there would be 2-6 pressure
reduction steps [309] to stabilize the crude.
1001541 Referring to Fig. 4 describes a system and method for crude
stabilization at
pressure to minimize emissions from oil production facilities. The wellhead
fluids [401] may
pass through zero, one or more pump(s) or compression device(s) [440] to
increase its
pressure to the operating pressure. Then the wellhead fluids may pass through
zero, one or
more flow control valves [443]. The flow control valve(s) [443] may be
actuated by a control
system or set manually or preset. The flow control valve(s) [443] may restrict
flow into the
system when one or more pressure sensors [444] indicated that there are gas
evacuation
constraints. The wellhead fluids are then sent to zero, one or more phase
separators [402].
These phase separators may be referred to as, but not limited to, allocation
separator, HI .13C
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separator, high pressure separator, test separator, heater treater, or
vertical separator. The
separator(s) [402] may collect wellhead fluid from one or more wellheads
[401]. The
separator(s) [402] may be a two-phase separator(s) or three-phase
separator(s). The wellhead
fluids may be chilled or heated by zero, one or more heaters or chillers or
heat exchangers
[441]. The heater(s), chiller(s) or heat exchanger(s) may be installed before
phase
separator(s) [402] or before phase separator(s) [406] or after phase
separator(s) [406]. The
separator(s) may produce three product streams: produced water stream(s) [403,
409],
gaseous hydrocarbon stream(s) [405, 407], and liquid hydrocarbon stream(s)
[434]. The
water stream(s) [403, 409] may contain some amount of hydrocarbons. The
gaseous
hydrocarbon stream(s) [405, 407] may contain some amounts of liquid
hydrocarbons and
some water. The liquid hydrocarbon stream(s) [434] may contain some amount of
gaseous
hydrocarbons and some water. The gaseous hydrocarbon stream(s) produced by the
separator(s) [405, 407] may go directly to one or more gas sales, evacuation
or use line(s)
[419], or it may be routed to one or more column(s) [410]. The gaseous
hydrocarbon
stream(s) may be routed to the top half of the column(s) [410] or to one or
more overhead
condenser(s) [427]. The name "overhead condenser" does not necessary indicate
that the
condenser is physically overhead. It merely connotates that the hydrocarbon
stream
originates at the top half of the column. The overhead condenser(s) [413]
chill the
hydrocarbon stream and route it to zero, one or more reflux drum(s) [414]. The
reflux
drum(s) separate the hydrocarbon stream to two or more streams. A gaseous
hydrocarbon
stream [430]. A water rich stream [415]. A liquid hydrocarbon stream [431].
The gaseous
hydrocarbon stream [430] may contain some liquid hydrocarbons and some water.
The water
stream [415] may contain some liquid hydrocarbons and some gaseous
hydrocarbons. The
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liquid hydrocarbon stream [431] may contain some gaseous hydrocarbons and some
water.
The gaseous hydrocarbon stream [430] may be routed to gas line(s) [419]. The
liquid
hydrocarbon stream [431] may be further divided [432] such that some of it
will be routed to
the top half of the column to be used as reflux fluid [416] and some of it
will be routed out of
the system [433]. The ratio between the amount of reflux fluid [416] and the
amount that is
routed out of the system [433], known as the reflux ratio, may be controlled
by zero, one or
more control valve(s) [432]. The reflux ratio may range between 0% (all the
liquid
hydrocarbon stream is routed out of the system) to 100% (all the liquid
hydrocarbon stream
will be injected back into the column as reflux fluid). The reflux ratio may
be determined
dynamically by a control system or manually or be preconfigured. The liquid
hydrocarbon
steam that is routed out of the system [433] may be blended with the gaseous
hydrocarbon
stream and routed to gas line(s) [419] or produced as an NGL stream [418].
[00155] The liquid hydrocarbon stream [434] enters the column through one or
more
injection point(s) [435]. The injection location of the liquid hydrocarbon
stream [434] may be
determined dynamically by a control system or manually or be preconfigured.
The
hydrocarbons at the bottom of the column are heated by a reboiler [426]. The
reboiler can be
controlled by a control system or set manually. The liquid hydrocarbon stream
produced by
the column [410] may be routed to zero, one or more sensor system(s) [436].
The sensor
system(s) may check if the liquid hydrocarbon stream would meet the crude
evacuation spec.
If the sensor system(s) determines that the liquid hydrocarbon stream would
not meet crude
evacuation spec, the liquid hydrocarbon stream may be routed back to the
beginning of the
process [437]. The routing of the off-spec liquid hydrocarbon stream may be
controlled by a
control system or manually or be preconfigured. The off-spec liquid
hydrocarbon stream may
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be routed to the bulk separator [406] or to the phase separator [402] or to
the column [410].
The routing of the off-spec liquid hydrocarbon stream may be determined
dynamically by a
control system or manually or be preconfigured.
1001561 The on-spec liquid hydrocarbon stream [438] may be cooled by zero one
or more
condenser(s) [425]. Cooling the liquid hydrocarbon stream "locks" the volatile
hydrocarbons
in the liquid phase producing stabilized crude that meets the crude evacuation
specs. In one
embodiment, the condenser [425] is implemented as a heat exchanger exchanging
heat with
the incoming stream [442]. This is known as an economizing heat exchanger. The
on-spec
crude can be routed to evacuation [421] or to one or more onsite crude tank(s)
[420]. Even if
routed to crude tank(s), the stabilized crude emissions would be minimal.
1001571 The water streams [403, 409, 412, 415] are routed to zero, one or more
water
tank(s) [422]. If the water stream is routed to water tank(s) [422], the
emissions from the
water [439] could be routed to one or more emission control device(s) [423].
The water can
then be sent to disposal [424].
1001581
Table 3 is a greenfield sample that reflects the state points on Fig. 4.
____ _______ITlid..õ_õ,*t!liL________ =!th13. 2.=.&,...14ii______ VF1.4
f:6tsxv_Stl'5t ________Watt. W"w__All_________ita ';ia."4. _____F='÷.."11:`?*
'`4Ei43:4.1._____
;.V*''6'.,,.".".'7........::....:i::.."'"..'V.W.:........."...."....7......g...
.....731Vgn:.......::i:v.v.:g.........
...:''..:i:......:i:......'............".......7..'S.:
.rg"........."..1;:.7.:MCM:n........"....... ..".."'*Y".........;"..'W
:4::4:z:::: ,s:::::::::::õ:,::: ::::: iiifig mo
;...s.4:>:
Act.....:,:..s, .F,,,,, .553inx n n.n S LW, :::.W.1,1 ICU
a.n
:WOW
Un...::.," b:,:.
:i.U.a: ....... ........ .. ... .. .. .. ........... .. ...
:,tRiSk:: '''':
::::'*.*
............ .... ....... : ..... :
...............,...
40.!k:::::. :::: :::: :21,..k=V.:*: : : :::
:,.`..tr.44.:S::.: ::: :::: :bii*,' :: :. ::: .:::: :::
'.'..;it'' : :::::;Si4 0i:::: : :....bg. ::::::::, ::::::;
Mem:, '.. , ,,.: $5..,: ,': 5; 6 ZAW.
,:.
4::,::::: S :If >Yr, ,:: WS.,
4...r:S2
00..,.. : OA:::: : iM:,.,. :ti:%.' :
,Z; OW : .. : '::=3' : : ::: .!...k, ,;:::]:::]
X=Viixi,rt :,:::: ik :,:,:::.: i:Ur,I,
i..VS.,:: t.ta$ .-.,,, .;.4., 1
!,,M.:
S N61 :.,.s.: 5.) 1.1D..i. ¶,:N.,4.-1 8
:.,E;4iLiLiOliWi:...........:3:AtEL,:ai.A.:.:M.Zii
Table 3
1001591 In one embodiment of the method, the system is collocated with one or
more
wellhead(s) on the same pad. In another embodiment, the wellhead(s) are
located in a remote
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location and the wellhead fluid is piped into the system. In that embodiment,
wellhead fluid
from multiple locations may be routed into one system. In yet another
embodiment, the
wellhead(s) and the phase separator(s) are located in a remote location and
one or more of the
phase-separated streams are piped into the system. In that embodiment, phase-
separated
streams may be routed from multiple locations into the system
1001601 The instant invention is furthermore a method and a
system for stabilizing crude
at higher than atmospheric pressure with the goal of reducing total emissions
from oil
production facilities comprising of:
a. One or more separation systems to separate the hydrocarbon liquids,
hydrocarbon gases and water,
b. One or more vertical separation systems utilizing a reboiler,
c. Optionally one or more reflux systems to further separate entrenched gases
from the liquid phase,
d. Optionally one or more systems that collect the overhead gases from the
first
and second systems and cool it to near ambient temperature,
e. Optionally one or more systems that separate the condensed liquids from the
third system into water, condensed hydrocarbons liquid and gaseous
hydrocarbons, and
f. An instrumentation and control system.
1001611 The method of the instant invention where the goal is to stabilize the
crude while
minimizing total emissions including fugitive emissions, combustion sources,
criteria
pollutants, venting, flaring and other greenhouse gas and hydrocarbon
emissions, from oil
production facilities.
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1001621 The method of the instant invention where the goal is to enable a
simpler
permitting process for new and old oil production facilities by reducing the
need to
control/flare/combust tank vapors and by reducing other sources of emissions.
1001631 The method of the instant invention where its goal is to stabilize the
crude to
maximize crude oil volume at or below the maximum allowable vapor pressure
1001641 The method of the instant invention where it can produce four streams:
produced
water, stabilized crude, optional NGL rich liquid or gas, and residue gas rich
in methane and
ethane.
1001651 The method of the instant invention where the system processes
wellhead fluid
from multiple wellheads.
1001661 The method of the instant invention where the system processes
wellhead fluid
from wellheads from multiple well pads.
1001671 The method of the instant invention where a compression system or a
pump is
added to increase the pressure of the fluids from the well.
1001681 The method of the instant invention where the wellhead fluid first
enters an initial
phase separator, such as a pre-well separator or an allocation separator, or a
test separator, in
front of the main horizontal separator.
1001691 The method of the instant invention where the initial phase separator
receives the
wellhead fluid from one well and the main phase separator and vertical
separator process the
output of the initial phase separators from multiple wellheads, for bulk
processing.
1001701 The method of the instant invention where the vertical phase separator
is a
distillation column.
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1001711 The method of the instant invention where the vertical phase separator
is a
stripping column.
1001721 The method of the instant invention where the gaseous streams produced
from the
horizontal phase separator(s) and vertical separator are combined.
1001731 The method of the instant invention where the gaseous streams produced
from the
phase separator(s) and vertical separator are chilled by an overhead
condenser. The
condensed liquid hydrocarbon fluid is accumulated in a reflux drum.
1001741 A method of the instant invention where a portion of the liquid
hydrocarbon fluid
accumulated in the reflux drum is used as a reflux fluid in the distillation
column.
1001751 The method of the instant invention where the gaseous streams produced
from the
phase separator(s) are not combined with the distillation column gas, but
rather the gaseous
stream from the phase separator(s) can be used for, but is not limited to,
injection into a
midstream sales line, for power generation, as fuel for heating, for gas lift,
for EOR, and/or
sent to flare.
1001761 The method of the instant invention where the fluids entering the
system are pre-
cooled. The cooling system is selected from, but not limited to, an air-cooled
heat exchanger,
a water-cooled heat exchanger, and a mechanical refrigeration system.
1001771 The method of the instant invention where the fluids entering the
system are not
pre-cooled.
1001781 The method of the instant invention where the fluids entering the
system are pre-
heated. The heating system is selected from, but not limited to, an economizer
heat
exchanger(s), an electric heater(s), or a gas fired heater(s).
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1001791 The method of the instant invention where the separation system to
separate the
three streams: produced water, liquid hydrocarbons and gaseous hydrocarbons,
is a heater
treater or three phase separator which may be of vertical or horizontal type.
1001801 The method of the instant invention where a portion of the gas output
stream is
used in one or more of several means, but not limited to, being sent to one or
more sales
lines, or is used for distillation column heating, or is used for fuel for
power generation, or is
used for gas lift or is used for EOR, or sent to flare.
1001811 The method of the instant invention where an overhead cooling
condenser is used
where the cooling system employs, but is not limited to, an air-cooled partial
condenser with
electrically driven fan(s) and finned tubing in its construction, or where the
cooling system
employs a mechanical refrigeration system.
1001821 The method of the instant invention where said separation system is a
three-
phase-separator which is a pressure vessel made specifically to efficiently
separate water and
hydrocarbon mixtures into distinct steams.
1001831 The method of the instant invention where the NGL fluid stream is an
off-spec
product that is neither Y-Grade NGL fluid nor L-Grade NGL
1001841 The method of the instant invention where the NGL fluid stream is spec
product
such as Y-Grade NGL fluid or L-Grade NGL fluid.
1001851 The method of the instant invention where the NGL fluid stream
contains trace
amounts (<10%) of condensate.
1001861 A method of the instant invention where the separator and the
distillation column
are integrated on the same skid.
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1001871 A method of the instant invention where the separator and the
distillation column
are not integrated on the same skid.
1001881 A method of the instant invention where the separator and the
distillation column
are integrated in a single vessel.
1001891 A method of the instant invention where the separator and the
distillation column
are not integrated in a single vessel.
1001901 A method of the instant invention where the separator and distillation
column are
not skid mounted.
1001911 The method of the instant invention where the horizontal separation is
a three-
phase separator.
1001921 The method of the instant invention where the horizontal separation is
a three-
phase separator with a large crude accumulation side that can be used as a
reservoir for the
reflux system.
1001931 The method of the instant invention where the horizontal separation
contains a
coalescer,
1001941 The method of the instant invention where the vertical system is
selected from,
but not limited to, a random pack column, or a tray column, or a valve tray
column or a
bubble cap column, or a sieve column.
1001951 The method of the instant invention where membrane separation is used
instead of
a column.
1001961 The method of the instant invention where the input to the column can
be diverted
to different locations along the column to optimize yield.
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1001971 The method of the instant invention where the column is split into
multiple
columns.
1001981 The method of the instant invention where a fractionation column also
fractionates the crude and gas into multiple components.
1001991 The method of the instant invention where multiple fractionation
columns
fractionate the crude and gas into crude components.
1002001 The method of the instant invention where the crude is heated by a
direct fire
heater.
1002011 The method of the instant invention where the crude is heated by an
electric
heater.
1002021 The method of the instant invention where the crude is heated by some
other
means than by a direct fire heater or by an electric heater.
1002031 The method of the instant invention where the temperature the crude is
heated to
is dynamically controlled by the control system.
1002041 The method of the instant invention where the temperature the crude is
heated to
is dynamically controlled by the control system with the goal of maximizing
the total crude
production by optimizing the vapor pressure of the crude leaving the system.
1002051 The method of the instant invention where the residue gas is produced
at pressure
higher than the midstream evacuation pressure.
1002061 The method of the instant invention where the overhead condenser uses
a
mechanical refrigeration system.
1002071 The method of the instant invention where the overhead condenser uses
an
ambient air-cooling system
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1002081 The method of the instant invention where the overhead condenser uses
a water-
cooling system.
1002091 The method of the instant invention where there is no overhead
condenser and no
reflux drum.
1002101 The method of the instant invention where the crude is sub-cooled by a
cooler
after leaving the column.
1002111 The method of the instant invention where the gas is sub-cooled by a
cooler after
leaving column.
1002121 The method of the instant invention where the stabilized crude is
sampled for
quality control, and if not meeting the required quality, it is recycled back
into the system.
1002131 The method of the instant invention where the control system throttles
the
incoming wellhead fluids based on its ability to evacuate the crude and gas.
1002141 The method of the instant invention where the control system is
remotely
connected via a telecommunication network to a remote operator.
1002151 The method of the instant invention where the remote operator can
control a large
number of systems on different locations.
1002161 The method of the instant invention where the remote operator can
prioritize
production of one site over another based on the capacity of the evacuation
pipeline.
1002171 The method of the instant invention where the control valves are
actuated using
instrument air or electric actuators.
1002181 The method of the instant invention where the produced crude is stored
in onsite
tanks.
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1002191 The method of the instant invention where the produced crude is
directly injected
into the crude midstream gathering line, bypassing the need for onsite tanks.
1002201 The method of the instant invention where the system measures the
quality of the
crude and pumps it directly into the crude midstream, bypassing the need for
onside LACT
unit.
1002211 A single-step-high-pressure system increasing overall
crude oil production by
selectively recovering butane and longer hydrocarbon chain components and
combining them
with the remaining crude providing conditioned, sub-cooled crude oil
comprising the steps
where:
a. wellhead fluid containing a mixture of hydrocarbons and water flow
through a
pressure regulating valve to stabilize system inlet flow,
b. the pressure stabilized stream enters the inlet three-phase separator which
is
equipped with coalescing technologies to reduce the settling time of the
water/hydrocarbon emulsion. the discrete hydrocarbon stream spills over the
weir and exits the separator,
c. bulk water is removed from the separator and is regulated through a control
valve for disposal,
d. the liquid hydrocarbon stream exiting the inlet three-phase separator is
regulated by a control valve into a distillation column which contains trays
or
is a packed bed or is of some other technology. Within the column, the
hydrocarbon mixture is separated by component boiling point,
e. the gaseous hydrocarbons exiting the inlet three-phase separator are
regulated
through a control valve, the gaseous hydrocarbons may mix with the
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distillation column vapor for further processing in the air-cooled condenser,
alternatively, the gaseous hydrocarbons may mix with the overhead phase
separator gas and exit the system without further processing, the flow path is
selected by two diverting valves,
f the light hydrocarbons exit the top of the column as a
vapor, the light
hydrocarbons enter an air-cooled condenser to generate a partially condensed
stream of hydrocarbons near ambient temperature, which are then separated in
an overhead phase separator.
g. vapor leaving the overhead separator is metered through a control valve as
conditioned gas,
h. bulk water is removed from the separator, metered through a control valve,
and mixed with upstream bulk water for disposal,
i. hydrocarbon exits the separator and is fed to a reflux pump, the pump
discharge is metered by a valve to maintain a steady reflux flow to maintain
product specification. Excess hydrocarbon liquid is optionally fed to an
injection pump for reinjection to the wellhead to increase oil production in
an
EOR process,
j. hydrocarbon liquid leaving the bottom of the column feeds a reboiler to
partially vaporize the liquid stream, the reboiler may be fired or electric,
reboiler operating temperature is determined based on desired crude oil
specifications, between 150 C and 400 C,
k. vapor exiting the reboiler is returned to the bottom of the distillation
column,
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1. liquids exiting the reboiler are metered through a
control valve and are cooled
to near-ambient temperature with an air-cooled heat exchanger,
m. a slipstream from the cooled crude is continuously analyzed with a vapor
pressure analyzer to verify product quality,
n if the cooled crude meets the vapor pressure
requirement, the crude product
flows through the product shutoff valve to be stored on-site, or to be
injected
directly into the crude midstream pipeline, and,
o. if the cooled crude does not meet the vapor pressure
requirement, the off-spec
crude is pumped through the off-spec recirculation valve to be reprocessed in
the feed separator.
1002221 A method of the instant invention where a stripping column is used
with no
overhead condenser and no reflux drum.
1002231 Since many modifications, variations, and changes in
detail can be made to the
described embodiments of the invention, it is intended that all matters in the
foregoing
description and shown in the accompanying drawings be interpreted as
illustrative and not in
a limiting sense. Furthermore, it is understood that any of the features
presented in the
embodiments may be integrated into any of the other embodiments unless
explicitly stated
otherwise. The scope of the invention should be determined by the appended
claims and their
legal equivalents.
1002241 In addition, the present invention has been described
with reference to
embodiments, it should be noted and understood that various modifications and
variations
can be crafted by those skilled in the art without departing from the scope
and spirit of the
invention Accordingly, the foregoing disclosure should be interpreted as
illustrative only and
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is not to be interpreted in a limiting sense. Further it is intended that any
other embodiments
of the present invention that result from any changes in application or method
of use or
operation, method of manufacture, shape, size, or materials which are not
specified within
the detailed written description or illustrations contained herein are
considered within the
scope of the present invention
1002251 Insofar as the description above and the accompanying
drawings disclose any
additional subject matter that is not within the scope of the claims below,
the inventions are
not dedicated to the public and the right to file one or more applications to
claim such
additional inventions is reserved.
1002261 Although very narrow claims are presented herein, it
should be recognized that
the scope of this invention is much broader than presented by the claim. It is
intended that
broader claims will be submitted in an application that claims the benefit of
priority from this
application.
1002271 While this invention has been described with respect to at least one
embodiment,
the present invention can be further modified within the spirit and scope of
this disclosure.
This application is therefore intended to cover any variations, uses, or
adaptations of the
invention using its general principles. Further, this application is intended
to cover such
departures from the present disclosure as come within known or customary
practice in the art
to which this invention pertains and which fall within the limits of the
appended claims.
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